In April 2017, Energy Secretary Rick Perry issued a request for the Department of Energy (DOE) to organize a study examining electricity markets and reliability.  The request was looking to explore three specific concerns: 1) The evolution of wholesale electricity markets, including the extent to which federal policy interventions and the changing nature of the electricity fuel mix are challenging the original policy assumptions that shaped the creation of those markets 2) Whether wholesale energy and capacity markets are adequately compensating attributes such as on-site fuel supply and other factors that strengthen grid resiliency and, if not, the extent to which this could affect grid reliability and reliance in the future; and 3) The extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.

As one may imagine, this request led a number of environmental and intermittent resource groups to question exactly what this exercise was attempting to accomplish and if its findings would be politically focused.  After months of abundant speculation, on August 23, 2017 the DOE released its findings.  While the principal conclusions of the study will not come as a surprise to those in the electricity markets, the study seems to take a solid “middle of the road” approach.

Perhaps most significant in this otherwise extensive and unclear report was that the DOE did not find that renewables are a threat to grid reliability and also did not obviously state that coal was necessary for grid reliability.  They specifically said, “Hydropower, nuclear, coal and natural gas power plants provide [essential reliability services] ERS and fuel assurance critical to system resilience”.  By grouping these fuel sources all together they relax the discussion around each of these fuel sources, predominantly coal and nuclear.

The main take away from the study is that favorable economics of natural gas-fired generation was the primary driver of baseload (i.e. coal and nuclear) power plant retirements.  Low growth in electricity demand (attributed to some permanent loss of load from the economic downturn and energy efficiency policies) coupled with the expansion of renewables on the grid have also played pertinent roles in baseload retirements.  The report also touched on adverse economic impacts of the requirements for regulatory compliance for some baseload plants.  DOE primarily named coal and nuclear costs to implement the  Mercury and Air Toxics Standard (MATS), the EPA’s Clean Power Plan and the Cooling Water Intake Rule as reasons cited for additional plant retirements.

The report was expected not only to analyze but also provide “concrete policy recommendations and solutions”.  In this space, the recommendations presented were less concrete and particularly vague.   The bulk of the recommendations focused on FERC.  Some of those suggestions included having FERC expedite their ongoing efforts with states, RTO/ISOs and stakeholder input to improve energy price formation , studying and making recommendations on regulatory mechanisms to compensate grid participants for services necessary to support reliable grid operations and working to expeditiously process LNG export and cross-border natural gas pipeline applications.  The report also calls on DOE and other Federal agencies to accelerate and reduce costs for licensing, relicensing and permitting of grid infrastructure like nuclear, hydro, and coal providing some hazy “specific reforms” for these technologies.

The DOE is looking for the public to submit comments regarding this study, although it is also unclear who is receiving these comments and how long this window will be open. The report will not end the ongoing debates in various states regarding whether nuclear and/or coal generation resources should be subsidized to ensure that all existing plants remain in operation, even if particular plants are inefficient or uneconomic.  It also fails to address whether wholesale market changes adopted after the Polar Vortex (such as PJM’s Capacity Performance product) are sufficient to provide the additional compensation and market signals to ensure generation reliability.

For additional information, please reach out to: Amy York (ayork@mcneeslaw.com) or Pam Polacek (ppolacek@mcneeslaw.com).

On May 18, 2017, House Bill 1405 was introduced into the Pennsylvania General Assembly.  The proposed legislation, which would restrict a municipality’s ability to utilize revenue generated by a municipal electric system, would significantly impact 35 municipalities in PA that purchase wholesale power on behalf of residents and distribute the power through municipal-owned electric distribution system.

Apparently, in response to complaints of high electric service costs from Ellwood City residents, HB 1405 was introduced to prohibit Ellwood City from using revenues from its purchased power and electric retail distribution services for any purpose other than paying the expenses for such services.  However, as currently drafted, HB 1405 would apply not just to Ellwood City, but to all 35 boroughs in the Commonwealth that purchase and distribute power for their local communities.  This bill would dramatically upset the status quo, as the Borough Code currently does not prevent boroughs from using electric service revenues to fund a variety of other operating expenses such as police, fire, and public works services.

In addition to banning the use of electric revenues to fund other municipal services or projects, HB 1405 would allow residents to challenge a borough’s electric rates in the local court of common pleas, restrict boroughs from adjusting electric rates more than quarterly, set rules for delinquent customer payment agreements, and prohibit termination of electric service for low-income customers during winter months.

Following its introduction to the House, HB 1405 was referred to the Committee on Local Government.  Various groups have announced support for the bill, including AARP, the Service Employees International Union, and the Pennsylvania Chapter of Americans for Prosperity (a tax reduction and deregulation advocacy group).  Opponents of the bill include the Pennsylvania State Association of Boroughs and the Pennsylvania Municipal League.

Of potential concern to many municipalities, HB 1405 would change the administration of borough-owned electric systems across the state based on complaints from customers in a single municipality.  Without expressing an opinion on the issues in Ellwood City, we note that many municipalities offer electric service to residents at competitive rates while also using electric revenues to fund general expenses that would otherwise require tax hikes for residents.

If you are interested in learning more about the status of HB 1405 and its impact on your municipal electric operations, please contact Adeolu Bakare at abakare@mcneeslaw.com or Kathy Bruder at Kbruder@mcneeslaw.com.

On July 8, 2017, The Pennsylvania Bulletin published a notice that the Pennsylvania Public Utility Commission (“PUC” or “Commission”) is seeking comments from stakeholders regarding electric distribution companies’ (“EDCs”) tariff provisions concerning the resale/redistribution of electric power to third parties.  Specifically, the PUC seeks comments regarding how those provisions would impact the operation and viability of electric vehicle (“EV”) charging stations.

Background on EVs in Pennsylvania

Over the past couple of years, the Commonwealth has witnessed an uptick in the number of registered EVs (rising from 1,653 vehicles in 2013 to around 3,600 EVs in 2016).  Although EVs continue to become more pervasive across the State, only 623 EV charging stations remain available to the public for recharging EV batteries.  As a result, the PUC believes all parties should take steps to foster increased investment in EV charging infrastructure across the State.  Accordingly, the PUC seeks comments from affected parties, particularly EDCs, on tariff provisions that account for EV charging stations.

Current Regulatory Framework Impacting EV Infrastructure

EV charging station owners purchase electricity from EDCs and resell that power to EV drivers with the goal of earning a profit from that sale.  The PUC believes that the current regulatory framework may restrict the ability of EV charging stations to earn a profit, which in turn would serve as a barrier to entry to this market.  Specifically, the PUC is concerned with Section 1313 of the Public Utility Code, 66 Pa. C.S. § 1313 (relating to price upon resale of public utility services), and EDCs’ tariff restrictions on resale/redistribution of purchased power.

Section 1313 indicates that an entity cannot resell power “to any residential customer” in an amount that exceeds what the EDC would bill its own residential customers for the same quantity of service under the EDC’s existing tariff.  On its face, this provision wouldn’t appear to impact an EV charging station owner because it resells power to an EV driver, not a residential customer. However, when viewed in connection with resale/redistribution provisions of EDCs’ tariffs, the PUC avers that Section 1313 may actually serve as a barrier to entry in this market by restricting EV charging stations’ ability to profit from sales of electricity to EV drivers.  EDCs’ tariffs vary widely and not all those tariffs address resales of power by a third-party EV charging station operators to EV drivers.  Further, some tariffs broadly permit the resale of power as long as it is compliant with 66 Pa. C.S. § 1313.

PUC Request for Stakeholder Comment on Potential EV Tariff Provisions

Because EVs continue to become more pervasive in Pennsylvania, the PUC believes all parties should take steps to foster increased investment in EV charging infrastructure.  As a result, the PUC seeks comments from affected parties, particularly EDCs, on the following topics:

  • What restrictions, if any, each EDC’s existing tariff places on the resale/redistribution of electric power by third-party EV charging.
  • The advantages and disadvantages of specific tariff provisions permitting unrestricted resale/redistribution of electric power when done for the purpose of third-party EV charging.
  • Whether it is appropriate to encourage EDCs across the state to move toward a tariff design which includes provisions permitting the resale/redistribution of electric power for third-party EV charging.
  • What other resale/redistribution tariff provision designs may aid in establishing clear rules for third-party EV charging stations.
  • What other regulatory options may aid in establishing clear resale/redistribution rules for third-party EV charging stations.

Comments on this issue are due to the Commission on August 22, 2017.  If you have any questions on this matter, please do not hesitate to contact any member of McNees’s Energy & Environmental Group or McNees’s Transportation, Distribution, and Logistics Group.

Under settlements approved by the Public Utilities Commission of Ohio (“PUCO”), many customers can reduce their transmission bills if they are capable of managing their contributions to the zonal single coincident annual transmission peak.

This opportunity arises out of the complicated system of regulation of electric services that has developed in Ohio.  As part of the introduction of competition in the sale of electricity in Ohio that became effective in 2001, Ohio law requires electric distribution companies to unbundle electric service into generation, distribution, and transmission services.

The price regulation of the services varies by service.  In general, the PUCO is without jurisdiction to regulate generation services prices, and generation service can be secured from competitive providers.  Distribution service can be secured only through the electric distribution utility and is priced through traditional cost-based regulation.

Transmission services, however, have developed in a more complicated legal environment.  Under Ohio and federal law, the electric distribution utilities retain ownership of transmission facilities, but operation of the facilities is placed with the regional transmission organization, PJM Interconnection.  The owners of the transmission facilities are compensated through federally mandated charges under the PJM Open Access Transmission Tariff (“OATT”).  The customers that pay these charges are load serving entities such as utility companies and competitive retail service providers and individual customers in states that have provided for competitive choice such as Ohio.  Under the OATT, these individual customers may contract either directly or indirectly through a competitive retail electric service provider for transmission service.

In recent years, however, several PUCO rate orders have frustrated the customer’s ability to contract for transmission services.  While the OATT authorizes a customer to directly or indirectly contract with PJM for transmission service and the Ohio Commission’s rules provide that transmission rates are to be bypassable (meaning that the customer may contract for transmission services when it contracts for generation service), the PUCO has approved for each electric distribution utility nonbypassable transmission rates for certain PJM costs including Network Integrated Transmission Service (“NITS”).

Because the PUCO has frustrated contracting for transmission services by authorizing nonbypassable transmission charges, customers lose the opportunity to manage their transmission charges.  This opportunity arises because the customer’s cost for NITS under the OATT is based on the customer’s contribution to the zonal single coincident transmission annual peak while the electric distribution utilities have been authorized by the PUCO to bill customers for NITS and other transmission costs based on a customer’s monthly billing demand.  For a customer that can manage its contribution to the zonal single coincident annual transmission peak, there is an opportunity to reduce the customer’s transmission cost.

A simple example demonstrates the potential for savings.  In the example set out in the table, the customer’s contribution to the zonal single coincident annual transmission peak is five MW, and its average monthly demand is 30 MW.  The example assumes that the OATT provides for a zonal single coincident annual transmission peak-based charge of $5/kW, while the electric distribution company charges $3/kW for transmission services based on the customer’s monthly billing demand.  Due to the differences in billing math under the OATT and PUCO approved rates for transmission service, the customer faces increased transmission charges of $780,000 annually under the PUCO approved rates than what it would pay under the OATT rate.

 

Monthly Demand Based Rate Monthly Demand Monthly Transmission Charge
$3/kW 30 MW $90,000
     
Zonal Single Coincident Peak-Based Rate Customer Contribution to the Zonal Single Coincident Annual Peak Monthly Transmission Charge
$5/kW 5 MW $25,000
     
Monthly Net Difference   $65,000
Annual Net Difference   $780,000

 

Because there are opportunities for substantial savings, McNees Wallace and Nurick attorneys have supported efforts for customers to have the opportunity to elect to purchase transmission service based on their contributions to the zonal single coincident annual transmission peak rather than their monthly demand.

These efforts have resulted in two approved transmission pilot programs that permit customers to seek to reduce the transmission portion of their bills.  A third pilot is under PUCO review.  The enrollment in each pilot program is limited, but the PUCO has indicated that it will entertain applications from additional customers.

One pilot program is available to a group of customers of the FirstEnergy utilities, Ohio Edison Company, Cleveland Electric Illuminating Company, and Toledo Edison Company.  Under this pilot, a customer may elect to contract for transmission service through its competitive electric generation service provider.  The second pilot, developed under a settlement with the Ohio Power Company, provides for alternative tariff rates based on the customer’s contribution to the zonal single coincident annual transmission peak.  A third proposal that would be available for customers of Dayton Power and Light Company is currently under review by the PUCO.

 

 

The Susquehanna River Basin Commission (“SRBC”) approved a final rulemaking at its business meeting on June 16, 2017, that will regulate “grandfathered” water withdrawals and consumptive uses as we explained in our analysis of the proposal last Fall.  This new regulation will be effective January 2018.  While the SRBC revised the proposed rule in response to public comments, the thrust of the rule will remain the same:  grandfathered withdrawals and uses will be required to register with the SRBC and to be metered.  The registration requirements for grandfathered withdrawals and uses will result in closer agency scrutiny.  They could cause loss of grandfathered status, triggering full SRBC review and approval for failure to timely register or increases in quantities withdrawn or used.

Entities with grandfathered sources and uses should carefully analyze this final rulemaking and contact McNees for additional information.

The new regulation is important for currently regulated and future projects.  There are changes to general application provisions and procedures that will be effective sooner than the grandfathering provisions (upon the rulemaking’s publication in the Federal Register) and could more broadly impact projects.

Other aspects of the proposed rulemaking last Fall, which would have imposed mitigation requirements for consumptive uses beyond the typical payment of a consumptive use mitigation fee, were abandoned in the final rule.  The SRBC removed proposed provisions relating to mitigation plans from the final regulation, including provisions on “water critical areas.”  The SRBC also put its draft Consumptive Use Mitigation Policy on hold, indicating that it will further consider the public comments on these issues and go back to the drawing board in the future.

We will know more about the final rulemaking when the SRBC posts the text and a comment/response document on its website in the coming weeks.  Until the grandfathering rule becomes effective in January 2018, the SRBC will be working on the forms and additional guidance for registration.  Once the grandfathering rule is effective, registrations can be made for six months without any application fee.

McNees contacts who can provide assistance include:

 

Capacity prices cleared PJM Interconnection LLC’s (“PJM”) most recent auction for the “rest of RTO” region of PJM at $76.53 per megawatt-day (“MW-day”) for the PJM delivery year beginning June 1, 2020.  The “rest of RTO” region represents all of the unconstrained zones of PJM and makes up the majority of the PJM footprint.  This is the second consecutive auction where capacity prices have declined in the unconstrained PJM zones, while at the same time PJM was implementing more stringent capacity rules under the “capacity performance product.”  The clearing price for the 2018/19 and 2019/20 delivery years was $164.77/MW-day and $100/MW-day, respectively.

For the first time, the Duke Energy Ohio and Kentucky zone (“DEOK”) was constrained with capacity clearing at $130/MW-day.  The Mid-Atlantic Area Council (“MAAC”), Eastern MACC (“EMAAC”), and COMED Load Delivery Areas (“LDAs”) were also constrained with capacity clearing at $86.04, $187.87, and $188.12/MW-day in those LDAs, respectively.  The higher price in the EMAAC LDA was driven in part by 2,300 MW of generation retirements.  The MAAC LDA includes Potomac Electric Power Company, Baltimore Gas and Electric Company, Metropolitan Edison Company, Pennsylvania Electric Company and PPL Electric Utilities.  The EMAAC LDA is a subzone of MAAC and is comprised of Atlantic Electric Company, Delmarva Power and Light Company, Jersey Central Power and Light Company, PECO Energy, Public Service Electric and Gas Company, Rockland Electric Company.

In addition to decreased capacity prices, PJM cleared a record high reserve margin of 23.3%, representing a 6.7% increase over PJM’s target reserve margin of 16.6%.

Overall the supply and demand balance in PJM remained largely unchanged from the prior auction, with a 2,196.7 MW reduction of cleared capacity (165,109.2 MW vs. 167,305.9 MW) offset by a 2,800 MW decrease in PJM’s reliability requirement driven by lower forecasted peak demand (153,915 MW vs. 157,188 MW).  Notable changes for supply side resources clearing the auction included year-over-year increases in new generation (2,389.3 MW), capacity imports (121.3 MW), and energy efficiency (195.1 MW), and uprates to existing generation (434.5 MW).  Notable year-over-year decreases included a reduction of cleared demand responses (2,527.6 MW), wind (81.3 MW), and solar capacity resources (209.7 MW).

PJM will conduct up to three additional incremental capacity auctions for the delivery year beginning June 1, 2020.  However, in the past the incremental capacity auctions have had little impact on the overall capacity price.

On May 17, 2017, the Pennsylvania Environmental Quality Board (“EQB”) greenlighted a proposal that would substantially increase fees for public water suppliers regulated by the Department of Environmental Protection (“PADEP”).  In addition to seeking the fee hike, the proposal would amend other regulations under the Pennsylvania Safe Drinking Water Act (“SDWA”), with some changes being even more stringent than federal standards.  The proposal now will be published in the Pennsylvania Bulletin followed by a public comment period of at least 30 days.

Stakeholders should carefully review the proposal and consider submitting comments, including all community water systems, noncommunity water systems, and bottled, vended, retail, and bulk water suppliers.  Those affected may include municipalities with water supply systems and businesses that supply water to the public or their own employees.

Fee Increase

The SDWA allows the EQB to establish fees for permit applications and certain services, as long as those fees bear a reasonable relationship to the actual cost of providing a service.  The proposal would amend the SDWA regulations by removing the current fee provisions and adding a new subchapter relating specifically to fees for each public water system.  PADEP has explained that the purpose of the fees is to increase the agency workforce tasked with inspecting public water systems, which would occur over the next few years.  When coupled with other costs of maintaining a reliable supply of water through permitting and technical requirements, such as those imposed by the Susquehanna River Basin Commission (“SRBC”), the financial impact on suppliers may be significant.

The proposed annual fees are generally broken down by type of water system and population served.  For community water systems, the proposed fees range from $250 to $40,000 depending on the population served.  The high end for noncommunity systems and vended, retail, and bulk water suppliers is $1,000, while the fee for bottled water systems is $2,500.  Public water suppliers will also be subject to additional fees for permit and technical reviews.  For example, application fees for construction or modifications would increase from the general $750 charge currently, to upwards of $10,000 under the proposal, again depending on system type and population served.

Other Amendments

Several other amendments have been proposed to keep pace with federal standards and, in some instances, go beyond federal standards.  Some of the regulatory proposals that are more stringent than federal requirements include:

  • Amended turbidity and filtration requirements to prevent turbidity spikes and pathogens.
  • System resiliency requirements for back-up power to ensure a continuous supply of water is delivered.
  • Clarifications to monitoring requirements for back-up sources and comprehensive monitoring plan requirements to ensure that all permitted sources are subject to routine compliance monitoring.
  • Requirements for responding to significant deficiencies through a protocol for notification and corrective action.

Public water suppliers should determine whether these and other provisions may apply to their systems and, if so, consider the potential impact.  McNees contacts that can provide assistance include:

Over the past few years, more businesses have begun to incorporate sustainability initiatives into their corporate cultures.  However, because energy costs represent a significant portion of a business’s operating costs, it is crucial to ensure that investments in renewable energy options align well with a business’s operations and budget.  Recently, McNees attorney Susan Bruce wrote an article on smart procurement strategies for businesses interested in pursuing sustainability goals while minding their energy costs.  If your company is interested in learning more about potential vehicles for renewable options, we encourage you to view Susan’s article and contact her with any questions at sbruce@mcneeslaw.com.  

We periodically report on matters that impact the costs large volume commercial, industrial and institutional customers pay for water/wastewater/stormwater service.  Below is information pertaining to a York Water Company matter before the Pennsylvania Public Utility Commission (“PUC” or “Commission”).

At the March 2, 2017, Public Meeting, the PUC voted to approve York Water Company’s (“York Water” or “Company”) plan for immediate replacement of both company and customer-owned lead service lines.  This permits York Water to replace customer-owned lead lines at its initial expense, and then recover the costs as a regulatory asset in the Company’s next rate case.

York Water’s most recent drinking water results exceeded the lead action level established by Pennsylvania regulations.  As a consequence, the Company became subject to a Consent Order with PaDEP that required specific action to reduce lead levels at customer taps.  Pursuant to the Consent Order, York Water proposed a two-phase plan to replace both company and customer-owned lead service lines.

The Commission granted the Company’s two-phase plan, permitting York Water to bear the costs of replacing customer-owned lead services lines, and to begin line replacement work immediately, consistent with the Consent Order.

Phase I involves replacement of customer-owned lead service lines discovered concurrently with York Water’s planned replacement of approximately 1,660 lead company-owned service lines in certain portions of the water system.  The estimated cost of replacing company-owned lead service lines is $2 million.  After replacement, the customer will continue to own the service line and be responsible for maintenance and repair.

Phase II involves annual replacement of 400 lead customer-owned service lines whenever they are discovered, over a period of nine years.  Under this phase, York Water would offer payment towards the replacement cost of the customer-owned lead service line.  As with Phase I, the customer will continue to be responsible for maintaining and repairing the service line after replacement.  In the event the number of Phase II replacements exceed those authorized, York Water must process them on a first-come, first-served basis.  However, if a water test exceeds 15 pbb of lead, then the Company may prioritize such replacement.

As to cost, York Water must make a payment towards the replacement cost of the lead customer-owned service line up to the Company’s average contracted cost.  For 2017, the average contracted cost is $1,150/service line replacement <10 feet and $1,250/service line replacement >10 feet.  Customers must pay any difference as a lump sum, or as an amount added to their bill, to be paid within one year.  The Company agrees not to charge interest on any payment period for the difference, other than late payment interest.  If the Company is unable to collect the difference from a customer, and the difference is written off as uncollectible, York Water will be permitted to include  uncollected amounts in the regulatory asset account.

The Company will offer a sliding-scale reimbursement to customers that have already replaced lead service lines within the past four years.  As such, a customer who replaced a line within one year may recoup 80% of the cost of replacement from the Company.  As the replacement grows older, reimbursement is less.

York Water must amortize amounts booked to the regulatory asset account in a base rate proceeding over a reasonable period (<6 years).  Amortization will begin on the effective date of new rates in a base rate proceeding.  York Water will reconcile amounts amortized to amounts incurred, and the difference must continue to be amortized in subsequent base rate proceedings.  The allocation among customer classes of the recovery of amortized costs will be determined in a base rate proceeding.

In closing remarks, Commissioner Powelson stated: “The importance of ensuring safe drinking water for all Pennsylvanians cannot be overstated.  However, in this post-Flint, Michigan world, it is not something we can take for granted.  I commend York Water for recognizing this, for taking the issue seriously, and for acting quickly to resolve it.  I encourage other utilities to do the same….”

However, it appears the PUC actions have not (yet) addressed the cost consequences on all ratepayers for lead-line replacement.  No legitimate reason exists for this cost to be passed on to large commercial or industrial customers; why this unvarnished fact was not now determined by this Commission is unclear, but suggests some contemplate these costs to be recovered volumetrically (as in the DSIC or CSIC) in which large commercial and industrial customers will shoulder most of the cost responsibility.

At McNees, Wallace, and Nurick, LLC, we often write of current or emerging issues that may have significant cost implications for large commercial, industrial and institutional end users in Pennsylvania.  We also closely monitor newly proposed legislation or regulation that may affect service rates, terms and use conditions.

For example, in 2016, we closely tracked HB 2114 introduced by Representative Mike Sturla (D-Lancaster).  It was captioned as follows: “Providing for registration of extraordinary nonagriculture and nonmunicipal water users; imposing a water resource fee; establishing the Water Use Fund; and providing for submission of a question to the electorate authorizing incurring of indebtedness for water-related environmental initiatives.”

This Bill defines “extraordinary water user” as “a person that withdraws more than 10,000 gallons of water a day from the waters of this Commonwealth for the purpose of for-profit business.”  In addition to a rather rigorous filing requirement, this Bill proposed a fee of $0.001 per gallon for water consumption greater than 10,000 gallons/day.”  In other words, this proposed legislation seeks to foist an additional $110,000/year on a large commercial/industrial customer using 10,000,000 gallons/month.  No mention is made in the Bill that some large volumes users (within the Susquehanna River Basin) have been paying a similar fee for some time. (See our earlier Blog articles regarding this issue.)

In 2016, this bill stalled in Committee; as such, by the end of the session, we believed the matter had been put downWe learned recently that plans exist for this same bill to be re-introduced later in 2017.  This is an important issue for large volume commercial and industrial users all of whom likely use far more than 10,000 gallons/day.

Recently, we learned that this bill is slated to be introduced in the second quarter of 2017 and may also include additional cost factors to be introduced in the upcoming Chesapeake Bay Commission meeting.  That meeting is currently slated for March 4 and 5, 2017, in Washington, DC.  Bill proponents are hoping to incorporate additional initiatives into what will be more expansive and far-reaching legislation.

This is yet one more example of the significantly increasing prices paid for provision of water and wastewater services, as they pertain to industrial, large commercial and institutional end-users.  This trend is likely, absent more vocal opposition from all affected end users, to continue in 2017 and beyond.

The Pennsylvania Statewide Water Users group is organizing an initiative to raise the awareness of lawmakers as to the potential impact of such legislation, and to coalesce if necessary, a group of impacted large volume users to provide testimony in opposition to such a significant cost increase.  If you would like more information, or if you have questions, please contact Jim Dougherty at 717.237.5249 or jdougherty@mcneeslaw.com.